The method, the densitometer and the multiphase meter of the invention are particularly suited to be used in the oil extraction sector.
It is known that the fluid produced from an oil-well is a mixture of oil, water and gas, therefore known in the technical jargon as a “multiphase fluid”.
In this field, it is required to determine the flow rate of the produced oil as accurately as possible, in order to quantify the actual profitability of the oil-well. The above determination is made by means of instruments commonly known as “multiphase meters”, suitable to determine the flow rate of the multiphase fluid and the oil fraction contained in it.
As regards in particular the oil fraction, this is calculated by means of known formulas as a function of the gas volume fraction in the fluid (GVF) and of the fraction of water in relation to the total liquid phase in the fluid, known as “water-cut” (WC).
It is evident that, in order to determine said two quantities, it is necessary to measure two mutually independent physical properties of the fluid.
The above mentioned physical properties must be measured as accurately as possible, in order to avoid that any measurement errors, propagating to the calculated oil flow rate, make said calculation unreliable.
According to a known technique, which is described for example in the International Patent application WO90/02941 by CHR. MICHELSENS INSTITUTT, the dielectric permittivity and the density of the fluid are measured, from which it is possible to obtain the gas fraction and the water-cut by means of known correlation equations.
Generally, density is measured by means of a penetrant photon beam, normally of the gamma type, conveyed through the pipe at the level of a measurement section.
The fluid partially absorbs the photons, thus determining an attenuation of the beam whose entity depends on the fluid density.
The number of photons passing through the pipe during a predetermined time period, named the “sampling period”, is counted, and divided by the number of photons which would pass through the pipe during the sampling period if the pipe were empty.
The above mentioned ratio makes it possible to determine the beam attenuation and, thus, to obtain the fluid density.
The above indicated calculation of density is affected by uncertainty, due to the fact that the photon emission from the source is a random phenomenon, subject to the known statistical Poisson distribution.
Accordingly, the number of photons emitted by the source during a sampling period of given length varies randomly, irrespective of the actual density of the fluid.
It is known that, for a Poisson statistical distribution, the uncertainty decreases as the number of counts per sample increases, i.e. as the source intensity and/or the length of the sampling period increase.
For example, in order to obtain a measurement of the signal with an uncertainty lower than 2% for at least 95% of the measurements, it is necessary to count at least 10000 photons per sample.
In fact, a 95% confidence corresponds to an uncertainty equal to twice the standard deviation of the sample size, i.e. the number of counts per sample, divided by the size itself, where the standard deviation (usually indicated as “sigma”) is the square root of the size of the sample.
Usually, in the oil production field, a sample size in the order of 100000 counts is used to obtain a measure with a small enough uncertainty.
Nevertheless, the maximum intensity of the radioactive source in a densitometer is limited due to the restrictions concerning the safety and the overall dimensions of the instrument, which in turn limit the average number of photons emitted by the source in the time unit.
Therefore, in order to obtain samples with the above mentioned size, it is necessary to use sampling periods with lengths in the order of one second.
Nevertheless, such sampling times are too long to allow for the detection of density changes due to the discontinuous gas flow through the pipe, because these changes occur in time intervals that are much shorter than one second.
Therefore, the aforementioned known technique poses the drawback of not being fast enough to allow the quick changes in the gas fraction to be measured with enough accuracy, only allowing average density measurements.
The above mentioned drawback increases the uncertainty regarding the density measurements, particularly for multiphase fluids in the oil production field.
In fact, since the oil fraction is related to the input values, i.e. the measured density and the electrical properties, through a highly non-linear correlation, the averaging of the input values causes a degradation of the result.
Moreover, since water and oil have much higher densities than gas, the overall density of such fluids decreases as the gas fraction increases, and the uncertainty of the density measurement become more relevant, in percentage, compared to the measured value.
Therefore, when the fluid flow is affected by quick changes in the gas content, the above described known technique is unable to give accurate density measurements, since these measurements also take into account the high gas content periods which, as just mentioned, cause high uncertainty in the measurements.
Since the water and oil densities are very similar, said uncertainty strongly affects the calculation of the water-cut and therefore the calculation of the oil fraction, causing the drawback of producing highly unreliable measurements.
What is described above is apparent from the diagram of FIG. 6, which expresses the uncertainty in the water-cut (ΔWC %) vs, the gas volume fraction in the fluid (GVF %), assuming the density measurement be affected by a 2% error.
In the attempt to remedy the above mentioned drawbacks at least partly, a further technique has been developed, which is described in the International Patent application WO2008150180 A2 by ROXAR FLOW MEASUREMENT AS.
According to this technique, the samples for the density measurement are collected during the low gas content periods only, while the photons detected during the high gas content periods are discarded.
This technique ensures, at least in theory, more reliable density measurements than the previous one since the density measurement corresponding to low gas content periods is affected by a lower degree of uncertainty.
The low gas content periods are detected through the measurement of an electric property of the fluid.
The above mentioned electric property measurement is much quicker than the density measurement, thus allowing to follow the instantaneous changes in the gas flow rate.
Despite allowing the uncertainty related to the presence of gas in the fluid to be reduced, the above technique nevertheless poses the drawback of noticeably increasing the duration of each density measurement.
In fact, since the photons corresponding to high gas content periods are discarded from the density measurement, it is necessary to extend the sampling period to several consecutive low gas content periods to obtain the predetermined number for each sample.
Nevertheless, these consecutive periods are distributed over an overall time period which is much longer than the actual length of the periods themselves.
Therefore, this technique doesn't allow the instantaneous monitoring of the water-cut, hence causing uncertainty when determining the oil fraction in the multiphase fluid.